Oil well production system



United States Patent 1,666,779 4/1928 Henceroth lnventor Appl. No.

Filed Patented Assignee 01L WELL PRODUCTION SYSTEM 8 Claims, 2 Drawing Figs.

Int. Cl

Field of Search References Cited UNITED STATES PATENTS 1,798,774 3/1931 Yates.... 2,903,088 9/1959 Spann ABSTRACT: The particular embodiment described herein as illustrative of one form of the invention includes in a gas lift well, a flow line for delivering output from the well to a separator. The output of a well on gas lift is normally in the form of a two phase fluid flow. The nature of a two phase fluid flow produces a substantial back pressure on the producing tubing string. This back pressure causes inefficiencies in the production of the well. A fluid phase separator in accordance with this invention is provided for separating the producing fluids into separate single-phase slugs to reduce the back pressure on the well, and to permit more efficient production of the well.

4- GAS PRESSURE PATENTED 0502219707 my ""GAS PRESSURE COMPRESSOR FIG.

INVEN TOR JOHN D. BENNETT ATTORNEY FIG. 2

OIL WELL PRODUCTION SYSTEM BACKGROUND OF THE INVENTION The present invention pertains to a system for producing oil wells, and more particularly to a system for separating a two phase fluid flow from a well into separate single-phase slugs. when gas pressure and volumes have so far declined that wells can no longer be made to flow their production through application of formational energy alone, it may yet be possible to continue operation by flow methods supplementing the formational energy with compressed gas forced into the well at the surface. Gas Lift in its various forms operates on this principie. The various methods of gas lifting have found wide application in the lifting of oil in many f elds, particularly during the stage of production intervening between the free flow and the time when the wells must be mechanically pumped.

The gas lifting of liquids is accomplished in one of two ways: 1. By continuous injection of gas into a tubing string (or casing annulus) at some predetermined dept-h, so as to lower the back pressure on the formation and allow fluids to flow continuously into the well, or 2. By the intennittent injection of gas into the well at a high instantaneous rate and for a short period of time to surface a column of fluid at regularly controlled time intervals. The former means of operations is designated as continuous flow, while the latter is referred to as intermittent flow. Intermittent gas injection can be accomplished by the use of operating valves which are placed in the downhole portion of the well to allow the-well to build up a fluid head between gas injections. in a-gas lift system, the wells are equipped with a column of tubing inside the casing. Com pressed gas is forced into the well at the casing head under sufflcient pressure to cause it to flow down between the tubing and casing. The gas enters the tubing through gas lift valves at the lower end of the tubing string, whereupon the body of liquids above the entryport forms a slug which moves up the tubing. As the lifting gas seeks a channelthrough the slug, the slug profile becomes more pointed. As the flow velocity reaches a peak, the slug breaks over into completely turbulent flow, whereupon, as the slug hits the wellhead at the surface, traveling at approximately 1,000 feet per minute, some of the liquid fallsback intothe tubing." I

In an alternative process, the gas may be injected into the upper end of the tubing, with production through the annular space between the tubing andcasing. The gas so introduced as a slug to lift the ascending stream of fluid becomes entrained in the oil slug above it to present a two phase flow. The volume of gas which follows the aerated slug to the surface is called lifting gas or tailing gas." Liquid oil in the tubing below the gas injection valve will feed past the valve into the tailing gas to also create atwo phase flow. g

in examining the pressure conditions within the well during a gas lift operation, it is assumed that back pressure on the formation is equal to the column of fluid within the well before the gas lift operation begins. Upon'lifting' a column of fluid towards the surface, an additional pressure is placed on the formation in an amount determined by the new .height reached by the level of the fluids in the tubing. As gas enters the eduction tube, there will be an additional but comparatively slight increase in pressure imposed on the reservoir rock until the fluid overflows on the surface. Some time check valves are used to prevent back pressure on theformatiomThe pressure developed at this stage, however, isno longer proportional to the height of the oil column, for the latter has acquired lower density by reason of the gas slugs.'Up to this point there has been a continual increase in back pressure on the production gas displacing the oil slug while the density of the oil-gas.

column in the tubing becomes lower and lower and the back pressure on the productive formation becomes less and less until eventually, if the conditions are favorable, the pressure maintained against the reservoir rock becomes less than the original static pressure established under the starting conditions of the well. Because of this reduced pressure, oil now begins to enter the well; and, as the pressure is further diminished, the quantity of oil flowing from the reservoir rock will increase until an equilibrium pressure gradient is established.

This equilibrium condition may be altered by injecting greater or more frequent volumes of gas, with the back pres sure on the productive formation diminishing as the increase takes place. This is limited however, by the flow resistance offered by the eduction tube, the resistance increasing as the flow velocity increases. it follows that, for a given size of eduction tube, there is a certain maximum volume of fluid that may be handled with a fixed amount of gas. if this volume can be increased by reducing flow resistance, then a greater amount of liquid may be produced with a given amount of gas, thus increasing the efficiency of the lifting operation.

it has been found from experience that by placing additional parallel flow lines into communication with the eduction tube, the reduction in flow resistance or back pressure on the eduction tube will cause the production efficiency of the well to increase. However, in a large gas lift system, there may be a considerable amount of pipe between the individual wells and the unit separator which serves the system of wells. As a result, placingparallel flow lines to the separator or increasing the size of such pipes would entail a considerable expense.

It is noted, however, that the flow from the eduction tube on a gas lift well is a classic two phase flow. with the liquid constituents being the continuous phase. One problem associated with two phase flow is the optimization of pipe sizes for theefficient transportation of such two phase flows. The two phase flow problem generally referred to here is that of the horizontal flow of such-fluids after they have been emitted from the upper end of the tubing string into horizontal flow lines. There are, of course, many different types of two phase flow regimes, depending amongst other things, upon, the ratio of gas volume to'liquid volume, the density of the fluids, and the velocity with which they areflowing' throughthe pipe. in horizontal flow lines, the force of gravity can effect the gas liquid distribution and leads to a different set of flow patterns from those for example, which would be associated with vertical flows. It is generally agreed, however, that a two phase flow, regardless of its composition, offers a greater differential pressure than that of a single-phase flow of fluids under the same conditions.

A look atthe mechanism of two phase flow will explain why pressure drops increase so much. When two phases flow through the same pipe, the gas usually flows faster than the liquid. The liquid accumulates in the pipe and reduces the cross-sectional area available for gas flow. The pressure loss of a fluid flowing through a pipe is inversely proportional to the fifthpower of the pipe diameter. The accumulated liquid in the same line has the effect of reducing the diameter. A reduction of 20 percent in diameter would cause a three fold increase in pressure drop, while a 60 percent reduction would increase pressure drop times.

The major factor causing high pressure drop is the energy required to move the liquid through the line. in most cases, this is energy supplied by the gas. Additional energy is used in the violent rising and falling of the liquid in the line. This expense of energy causes a reduction in system pressure. When this factor is combined with the effects of pipe diameter and roughness, it becomes more apparent why large pressure drops occur in two phase flow patterns. Although liquid holdup could increase pressure drop many folds, it does not account for all the loss caused by the two phase flow. when the interface between the gas and oil is smooth, the energy lost by the gas to the liquid surface is about the same as would'be lost to a smooth pipe wall. This energy is transferred to the liquid at almost 100 percent efficiency, and is the source of the energy used in moving the liquid along the pipe. When gas velocity increases, waves begin to form on the surface of the liquid. The heights of the waves increase with increased velocity until they almost equal the diameter of the pipe. At atmospheric pressure, doubling the difference in velocity between the gas and liquid may reduce the efficiency of energy transfer to 50 percent. The lost energy is dissipated in making the waves of liquid. These liquid waves create a situation analogous to roughness in a pipeline. Various friction factor charts, depending on the Reynolds Number Level, show that pressure drop for very rough pipes may be two to tenfold greater than for smooth pipes.

It is therefore an object of the present invention to control the back pressure on a fluid flow system by converting a two phase flow into an intennittent single-phase flow.

SUMMARY OF THE INVENTION With this and other objects in view, the present invention contemplates, in an oil and gas production system, a well tubing producing a two phase hydrocarbon flow into a flow line for transmission to a central processing station.. Included in the flow line at the wellhead is a chamber connecting the flow passage from the well. The flow passage enters the chamber, which may be in the form of a cylinder, at a position tangential to the side walls of the cylinder. The outlet end of the chamber is slightly lower than the input end, and is restricted in cross section to that of the flow line to the processing point. The two phase fluid flowing into the chamber tends to spiral about the interior wall of the chamber so that the liquid will spin and be thrown to the outside diameter and the gaseous phase of the flow will pass through the center of the chamber. This will allow the gas to quickly bleed down through the chamber into the output line to be followed by the liquid phase of flow which is pushed on out through the flow line by tailing gas in the system.

The novel features of the present invention are set forth with particularity in the appending claims. The present invention, both as to its organization and manner of operation, together with further objects and advantages thereof, may best be understood by way of illustration'and example of certain embodiments, when taken in conjunction with the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS FIG. 1 is a schematic illustration of a typical gas lift oil producing system; and

FIG. 2 is a schematic representation of a producing well and a phase separation system in accordance with the present invention.

DESCRIPTION OF THE PREFERRED EMBODIMENTS FIG. 1 of the drawings shows a schematic view of a typical system for use in injecting gas into wells for lifting purposes and for producing liquid and gas constituents therefrom. The system includes a plurality of producing wells 11, with individual production lines 12 emanating therefrom. The individual production lines converge into a single gathering line 13 for carrying fluids produced in the wells to a liquid gas separator unit 14 of any well known type, for separating the liquids and gas constituents of the producing fluids. A liquid output line 16 from the separator carries the liquid constituents of the fluid to a transporting means such as an oil pipeline for conveying such liquid products to a refinery or the like for processing. The second output line 17 from the separator carries gaseous constituents of the produced fluids to compressors 18 which compress the gas and discharge it into a pressure gas line 19. The pressured gas is then returned through the pressured gas line for injection into the wells 11,

while a portion of the pressured gas may be diverted through a gas product line 21 for transmission to a gas sales point. A fluid phase separator 22 is positioned at each wellhead in the production line 12 from the well for separating the phases of the fluids prior to their movement through the output and gathering lines.

In the operation of a typical gas lift system, the input gas of the well is injected into the well normally through the annular space between the tubing and the casing. The lifting gas then passes from the casing annular space into the tubing through one or more gas lift valves which are spaced vertically within the tubing string. Control devices are positioned at each wellhead site to facilitate injection of gas into the casing annulus. Such control devices are typically comprised of a timing mechanism and a pressure regulator. The pressure regulator may be set so that the gas injection will not take place unless the pressure of the gas to be injected is at a predetermined level. The downhole injection valves are also pressure operated to act in an intermittent manner, and thereby inject separated volumes of gas to separate slugs of liquid in the tubing. The intermittent injection of gas into the tubing lifts the slugs of liquid product from the bottom of the wellbore to the surface and out through the flow lines to a gathering line.

The tailing gas slug expands to aerate the slug of formation fluids as it moves up the tubing string to the surface. The slug of produced fluid is then fed to a liquid gas separator. Liquid gas separators utilize various means to knock out the liquid constituents of the produced fluid so that they may be drained therefrom for transportation to an oil sales point, such as a refinery. The gas constituents may then be passed into a compressor where the gas pressure is raised to a sufficient level for injection of gas back into the wells or for transportation to a gas sales outlet, such as a gasoline plant. During the injection of gas into wells for lifting purposes, if the pressure at the well head is not at a predetermined level, desirable for such gas lift operations, the gas lift injection valve will not open and will remain closed until such pressure has built up to the level desired. In this event, the delayed injection or kick may be timed to coincide with the injection of gas into another of the wells, to thus provide a simultaneous injection of gas into more than one well. In this event, a greater than normal amount of fluid constituents are produced from the wells during a single period and enter the gathering lines for transmission into the separator. The separator which is designed for a sequential production of wells may become overloaded by such simultaneous kicks. In this event, the liquid constituents of the fluid may not be sufficiently removed in the separator, and as a result, the gas being passed on through the system may have a considerable amount of liquid entrained therein.

In the system of the present invention, the fluid phase separator, which is positioned in the product output line at each wellhead, not only reduces the back pressure on the lifting fluids within the wells, but also accomplishes a degree of fluid separation prior to entry of the producing fluids into the conventional separator. This, in turn renders the conventional separator operation more efficient in order to handle such occurrences as simultaneous injection of gas into more than one well which may tend to overload the separator during normal operations.

The apparatus for accomplishing the fluid phase separation and its method of use are best described with reference to FIG. 2 of the drawings. A wellbore 31 is shown extending from the earths surface into a producing formation underground. The wellbore is cased, with the casing having perforations 32 at its lower end for permitting formation fluids to enter the interior of the casing. A string of tubing 33 is shown extending from the upper end of the casing into the well, with its lower end positioned at or just above the producing zone. A packer 34 is positioned on the tubing between its lower end and the interior walls of the casing to separate fluids entering the casing through the producing zone perforations from fluids in the annular space between the tubing and easing above the packer. An input gas line 36 is connected with the upper end of the casing head. Gas lift valves 37 of any well known type are spaced vertically in the tubing string to facilitate lifting of fluids therein in stages. As gas is introduced into the tubing string, the slug 23 of formation fluids which has collected in the pipe above the valve is lifted toward the surface. The tailing gas slug 24, which partially aerates the formation fluid slug, follows the slug 23 to the surface.

At the surface, the tubing or eduction tube for lifting well fluids terminates in an output pipe 38, which is shown as being a circular member. The outer end of such output pipe is open, and inserted within a substantially horizontally disposed cylindrical chamber 39. The pipe enters the chamber at an angle from the vertical, and also is positioned so that output fluids from the pipe will strike the interior wall of the chamber tangentially. The result of the positioning of such output pipe with respect to the cylindrical chamber is that fluids emanating from the pipe will thread or spiral along the inner wall of the pipe downwardly to the output end 41 of the chamber. Normally the output end of the chamber is positioned at a lower elevation than the input end to facilitate the gravity drainage of liquids therein towards] the output end. The production line 12 which emanates from the bottom side of the lower end of the cylindrical chamber is connected into the flow line system for transporting the fluids to the conventional separator 14. f l

As a result of the positioning of the output pipe 38 from the well with respect to the cylindrical chamber 39, and am result of the fluids entering the chamber at a high velocity, i.e. [,000 feet per minute, such fluids'emanating from the output line swirl around and down the length ofthe chamber, which tends to force the liquid constituents therein outwardly against the walls for swirling along the interior wall of the chamber, while the gaseous constituents are free to expand into the center of the chamber and flow out the outputend. Thus the chamber in effect separates liquid and gaseousphases of the fluids into slugs,'wherein as the gas is separated and enters the center of the chamber, it exits the chamber first so that the fluids which have been centrifuged out of the fluid will then drain to the lower end of the chamber, where they will form a liquid slug which will be passed out the output pipe and propelled therealong by means of the tailing gas entering the separating chamber. The chamber is sized to accommodate the normal volume of fluids which are produced during one gas lift cycle.

Since single phase fluids flow more efficiently than two phase or multiphased fluid systems, the product of the phase pended claims is to cover all such changes and modifications as fall within the true spirit and scope of this invention.

lclaim: i

1. In a well production system: pipe means in a wellbore and extending downwardly from the surface to a formation fluid level within the wellbore; means for injecting gas into said pipe means for lifting the formation fluids to the surface; a substantially horizontally disposed elongated cylindrical chamber positioned at the surface; conduit means for providing fluid communication between the pipe means and the chamber,

' said pipe means connecting with the chamber at an angle to means connects with a liquid gas separator.

3. The apparatus of claim 1 wherein said elongated cylindrical chamber means has one end lower than the other with said separation system will offer less resistance toflow in the lines, I and as a result, the back pressure uponthe gas lift system will be decreased. This in turn will decrease the pressure on the producing zone and will permit a greater rate of production from'the formation. In addition, the fluid phase separator performs a step of separating the liquid and gas whichis also a function of the conventional separator system, so that in the event the separator system. would normally become overloaded, the provisions for separating the liquid and gaseous phases into alternate slugs should aid the separation step to such degree that the separator will not become overloaded under the same conditions.

While particular embodiments of the present invention have been shown and described, it is apparent that changes and modifications may be made without departing from this invention in its broader aspects, and therefore, the aim in the apoutput means connected to the lower end.

4. The apparatus of claim 1 wherein said chamber is sized to accommodate a volume of fluids produced from a well during a gas lift cycle. u

5. In a well production system including wells being gas lifted and flow lines connecting the output of such wells with a liquid gas separator, means for reducing the back pressure imposed upon such wells, which means comprises: an elongated substantially horizontal cylindrical chamber disposed in the flow line emanating from a well; said flow line entering one end of said chamber and having a single outlet disposed at an angle to the longitudinal axis of said chamber and tangentially to the inner wall of said chamber; and a conduit connecting the other end of said chamber with the liquid-gas separator.

6. A method for producing a two phase fluid flow from a well in such a manner as to reduce back pressure on the producing fluids, comprising the steps of: passing the two phase fluid flow from the well into a cylindrical vessel, spiraling the entering two phase fluid flow about the inner peripheral wall of the chamber so that the gaseous phase of the fluid is permitted to escape to the center of such chamber; passing the gaseous phase as a first slug through an exit line from such chamber; and subsequently passing the liquid phase as a second slug through the same exit line.

7. The method of claim 6 wherein .fluid slugs exiting the chamber are passed into a liquid-gas separator.

8. A method for producing fluids from an oil well including:

moving producing fluids in a two phase fluid flow from the oil well through a pipe; passing such moving fluids into a chamber such that the entering fluids strike the chamber at an angle to its longitudinal axis and tangentially into the inner peripheral wall of said chamber, the positioning of such entering fluids relative to said chamber causing such fluids to initially spiral about the inner peripheral wall of such chamber wherein the liquid constituents are centrifuged to the wall of the chamber and the gaseous constituents are permitted to escape to the center of such chamber; and passing the separated liquid and gaseous phases out of the chamber through a single pipe as alternate slugs of gas and liquid. 

